OGA Measurement Guidelines 20203.2.1 Direct measurement approaches may be regarded as adopting the following hierarchy (in ascending order of measurement uncertainty): (i) Continuous

January 2020

OGA Measurement Guidelines 2020

1. Introduction 3

The OGA 3

The OGA’s Metering Team 4

Contact Details 4

2. Overview of the OGA Regulation of Fiscal Oil and Gas Measurement and Allocation 5

Pipeline Export Systems 5

Allocation Measurement 5

Offshore Loading Systems 5

Additional Guidance 6

3. Petroleum Operations Notice 6 (PON 6) 7

Method of Measurement 7

Initial Meeting 7

Approval to Proceed with Design 8

Testing and Calibration Activities 8

Final PON 6 Submission 8

Formal Non-Objection from the OGA 8

4. General Operating Principles 9

Risk-Based Maintenance Strategies 9

5. OGA Inspection of Fiscal Oil and Gas Measurement and Allocation Systems 10

Inspection Planning 10

Inspection Format and Follow-Up 10

UK/Norway Memorandum of Understanding 10

6. Dispensation and Deviation Management 11

Dispensations 11

Deviations 11

7. OGA Pipeline Reviews 12

Metering Station Performance 12

Pipeline Management 12

8. Offshore Loading Systems 13

Definitions 13

OGA Measurement Expectations 14

OGA Reporting Requirements 14

Contents

9. Production Separator Measurement for Allocation Purposes 16

Introduction 16

Separator Design 16

Separator Capability 16

10. Test Separator Measurement for Allocation Purposes 18

Introduction 18

Test Separator Design 18

‘Flow Sampling’ – Well Test Procedures 18

Multiphase Measurement – MPFM/ Test Separator Comparison Procedures 18

11. Multiphase Measurement in Allocation Applications 20

Typical Applications of MPFMs 20

Meter Selection 21

Service and Maintenance Agreements 22

Onshore MPFM Calibration 22

Onshore Calibration – Static Testing 22

Onshore Calibration – Flow Loop Tests 22

System Integration Test 22

Offshore Calibration – Static Testing 22

Comparison of MPFM with Test Separator 23

VerificationTechniques 23

Sampling 23

12. Wet Gas Measurement in Allocation Applications 24

Differential Pressure Meters 24

Determination of Gas and Liquid Density 24

Determination of Liquid Content 25

Comparison of Wet Gas Meter with Test Separator 25

13. Well Flow Rate Determination for Reservoir Management Introduction 26

Factors Affecting Well-Test Results 26

Effect of Bias and/or Uncertainty in Well-Test Results 27

OGA Review of Well Testing 28

3 1. Introduction | OGA Measurement Guidelines 2019

1.1 The Oil & Gas Authority

1.1.1 The Energy Act 20161 created the Oil & Gas Authority (‘OGA’) as an independent regulator and transferred some of the Secretary of State’s regulatory responsibilities, including petroleum licensing, to the OGA.

1.1.2 TheroleoftheOGAistoregulate,influenceandpromote the upstream oil and gas industry in the UK so that it achieves the statutory principal objective of maximising economic recovery from the UK’s oil and gas resources (MER UK). (See https://www.ogauthority.co.uk/ for further information.)

1.1.3 DetailsoftheUK’sfiscalregimeforupstreamoiland gas activities may be found at the following URL: https://www.gov.uk/topic/oil-and-gas/finance-and-taxation

1.2 Status and Purpose of the Guidelines

1.2.1 Production licences contain provisions in relation to the measurement of petroleum including a requirement that: “The Licensee shall measure or weigh by a method or methods customarily usedingoodoilfieldpracticeandfromtimetotime approved by the OGA all petroleum won and saved from the licensed area.”

1.2.2 The purpose of these Guidelines is to set out the OGA’s expectations as to what will generallyconstitute‘goodoilfieldpractice’forthefullrangeoffiscalmeasurementscenariosthat are likely to be encountered in practice. The Guidelines also set out the procedure that licensees should follow to gain the OGA’s approval of their methods for petroleum measurement.

1.2.3 While responsibility to comply with the licence obligations in relation to the measurement of petroleum rests with the licensee, the OGA recognises that in practice these matters may be undertaken by the operator, on behalf of the joint

venture. The OGA therefore expects operators to similarlyadheretotheprinciplesof‘goodoilfieldpractice’ and the terms ‘licensee’ and ‘operator’ are used interchangeably in these Guidelines.

1.2.4 With the exception of Chapter 13, these Guidelines apply to measurement systems used to determine quantities of petroleum won and saved from licensed areas both onshore and offshore in the UK.

1.2.5 The Guidelines should be interpreted as representing general minimum expectations. They should not be viewed as prescriptive.

1.2.6 The Guidelines are not a substitute for any regulation or law and are not legal advice. They do not have binding legal effect. Where the OGA departs from the approach set out in the Guidelines, the OGA will endeavour to explain this in writing to the relevant Operator or licensee.

1.2.7 The Guidelines will be kept under review and may be amended as appropriate in the light of further experience and developing law and practice, and any change to the OGA’s powers and responsibilities.

1.3 The OGA’s Metering Team

1.3.1 The OGA’s Metering Team helps to ensure the delivery of the MER UK objective by taking a risk-basedapproachtotheregulationoffiscaloil and gas measurement. The OGA’s focus will beontheareasofgreatestfiscalrisktotheUKExchequer, including:

• Points of sale of hydrocarbons produced on the UK Continental Shelf

• Measurement and allocation in shared transportation systems containing non-UKCS (principally, Norwegian) hydrocarbons

1. Introduction

1 http://www.legislation.gov.uk/ukpga/2016/20/contents/enacted

4 1. Introduction | OGA Measurement Guidelines 2019

1.3.2 At the same time, the OGA encourages Operators to themselves adopt risk-based approaches in the design and day-to-day running of their measurement stations.

1.3.3 In addition, the OGA’s Metering Team is taking anincreasedinterestinmeasurementofflowratesfromindividualwellsforfield-andreservoir-management purposes.

1.4 Contact Details

1.4.1 Contact details for the OGA’s Metering Team are to be found at the following URL: https://www.ogauthority.co.uk/exploration-production/production/petroleum-measurement/

1.4.2 General communications to the OGA’s Metering Team should be sent to: [email protected].

5 2. Overview of OGA Regulatation of Fiscal Oil & Gas Measurement & Allocation | OGA Measurement Guidelines 2019

2.1 Pipeline Export Systems

2.1.1 Most hydrocarbons produced on the UKCS are exported to market via shared transportation systems (pipelines), with the quantities measured at the terminal being allocated to each entry point on the basis of measurements of quality and quantity at the respective metering stations.

2.1.2 The design and operating requirements at the terminal and at the pipeline entry points are typically determined by the relevant pipeline operating agreement, covering areas such as:

• measurement uncertainty

• sampling and analysis procedures for the determination of hydrocarbon quality (for liquid hydrocarbons) or energy value (for gaseous hydrocarbons)

• determination of water content (for liquid hydrocarbons)

• calibration of primary and secondary instrumentation

• periodic inspection of the measurement station by an independent authority

2.1.3 From time to time, the OGA may review the management of measurement activities by pipeline operators, with particular emphasis on the following areas:

• pipeline balance

• scheduling and follow-up of independent audits of measurement stations at pipeline entry points

• dispensation and deviation management

• adoption of risk-based versus time-based maintenance strategies

2.2 Allocation Measurement

2.2.1 Further to the allocation of production to primary entry points, secondary and even tertiary sub-allocation of commingled production to licensed areas may take place. There is typically no pipeline-wide requirement on standards at

these secondary and tertiary measurement points; instead, the method of measurement and allocation is agreed between the Operators and LicenseesoftherelevantfieldsandtheOGA,at the Petroleum Operations Notice 6 (PON 6) stage (see Chapter 3). This document contains guidance on the approaches that are likely to be acceptable under such scenarios, in the chapters on separator, test separator and multi-phase/wet gas measurement.

2.3 Offshore Loading Systems

2.3.1 Where liquid hydrocarbons are exported direct to market with the point of sale at the port of discharge, the OGA is generally content to relyontheterminalOutturnfigures.Operatorsare asked to provide the OGA with the cargo transferfiguresatkeypointsinthevaluechain(See chapter 8).

2.4 OGA Tier Zero Reviews

2.4.1 Operators’ performance in managing the operationoftheirfiscalmeasurementstationsispart of the OGA’s Stewardship Review process2. A number of key performance indicators, for example:

• performance at the OGA inspections

• progress in closing out points raised during inspections by the OGA or independent pipeline auditors

• progress in closing out dispensations within initially-agreed timeframes) are fed into the Tier Zero review

2. Overview of OGA Regulation of Fiscal Oil and Gas Measurement and Allocation

2 https://www.ogauthority.co.uk/media/3540/stewardship-review.pdf

6 2. Overview of OGA Regulatation of Fiscal Oil & Gas Measurement & Allocation | OGA Measurement Guidelines 2019

2.5 Additional Guidance

2.5.1 Valuable guidance on best practice in measurement and allocation applications is provided by the following:

(i) The proceedings of the annual North Sea Flow Measurement Workshops3.

(ii) The Energy Institute publications in the ‘Hydrocarbon Management’ series. Details of these can be found at the following URL: https://publishing.energyinst.org/topics/hydrocarbon-management

3https://nfogm.no/documents/north-sea-flow-measurement-workshop/

7 3. Petroleum Operations Notice 6 (PON 6) | OGA Measurement Guidelines 2019

3.1.1 Guidance on the OGA’s Field Development Plan (FDP) expectations is available on the OGA website4

3.1.2 The FDP submission may include a basic statement on the proposed method of measurementfortherelevantfield.Inadditionto the FDP, an additional document, known as the Petroleum Operations Notice 6 (PON 6), is required.

3.1.3 The preparation of a PON 6 submission is an iterative process, the purpose of which is to establish in writing an agreed method of measurementforthefield.

3.1.4 ThefinalcontentofthePON6mustbeagreedwith the OGA prior to the start of production fromtherelevantfield.

3.1.5 The level of information required by the OGA dependsonthescaleofthefielddevelopmentunder consideration and on the proposed hydrocarbon export route.

3.1.6 Where the hydrocarbon export route is directly into a shared transportation system, the method of measurement is likely to be determined by the need to comply with the pipeline entry specifications.In such cases, the OGA will generally restrict its regulatory input to ensuring that the Licensee complies with the relevant pipeline entry requirements

3.1.7 Fornewfielddevelopmentswherethefiscalmeasurement point will be a secondary or tertiary allocation point, the OGA shall at each stage in the procedure seek assurances that the proposed method of measurement is acceptable to the other interested parties. In assessing the exposure in more complex multiple-entrant allocation systems, it may be useful to consider theresultantuncertaintiesnotjustinfieldterms,butalsointermsofthefinancialexposuretoeach equity holder in the system.

3.2 Method of Measurement

3.2.1 Direct measurement approaches may be regarded as adopting the following hierarchy (in ascending order of measurement uncertainty):

(i) Continuous single-phase measurement of each phase, post-separation, in dedicated meter runs designed to minimise measurement uncertainty.

(ii) Continuous, nominally single-phase, measurement of each phase on the oil, gas and water off-takes of a dedicated separator.

(iii) Continuous multiphase or wet gas measurementviaadedicatedflowmeter, installed either topsides or subsea multiphase.

(iv) Intermittent, nominally single-phase, measurement of each phase on the oil, gas and water off-takes of a test separator, with interpolationoftheflowratesofeachphaseduring the periods between these ‘well-tests’ –‘flowsampling’.

3.2.2 In some circumstances, a ‘by difference’ solutionmaybeappropriate,providedthefieldin question is a relatively large proportion of the commingled total.

3.2.3 The optimal measurement solution is one where the desirability of low measurement uncertainty isweighedagainsttheeconomicsofthefielddevelopment in question.

3.3 Initial Meeting

3.3.1 Foranewfielddevelopment,theLicenseeshould present its proposals to the OGA at an initial meeting. From the above it should be clear that the measurement approach is fundamental tothenatureofafielddevelopment.Therefore the meeting should take place at as early a stage as possible, and certainly prior to the submission of the Field Development Plan to the OGA.

3. Petroleum Operations Notice 6 (PON 6) Process3.1 blank title

4https://www.ogauthority.co.uk/exploration-production/development/field-development-plans/

8 3. Petroleum Operations Notice 6 (PON 6) | OGA Measurement Guidelines 2019

3.3.2 In considering the proposed measurement approach, the OGA will take account of the specificeconomicandtechnicalaspectsoftheproposedfielddevelopment.Atthisstage Licensees should provide the following information (together with any other information requested by the OGA):

• Thereservesandanticipatedproductionprofileofthefield.

• Aprocessflowdiagram,indicatingthelocationof the proposed metering and sampling points. Where‘satellite’fieldsarebeingconsidered,details of any space and weight constraints on the ‘host’ facility should be included.

• Details of the proposed measurement and allocation approach, including the metering and sampling technologies, along with an approximatemeasurementuncertaintyfigure.

• Details of the proposed method and frequency ofre-verificationofthemeteringtechnology.Where it is intended to adopt elements of a ‘condition-based maintenance’ strategy, this should be considered at the design stage as it may necessitate the use of additional measurement points and/or dual instrumentation.

3.3.3 Further to the initial meeting, the OGA may requireLicenseestocarryoutacost-benefitanalysis so that the optimal method of measurement may be determined. In such cases,thecost-benefitanalysismustbesubmittedatasufficientlyearlystagethatnoneof the options under consideration would involve adelayinfirstoiland/orgas.

3.4 Approval to Proceed with Design

3.4.1 Once the measurement approach has been agreed in principle, the Operator will be given approval to proceed with the detailed design. The approval will normally take the form of a note making reference to material presented by the Operator during the initial meeting, and/or anysubsequentcost-benefitanalysis.

3.5 Testing and Calibration Activities

3.5.1 Prior to its installation and on-site commissioning, the Operator should be able to demonstrate to the OGA, if requested, that the criticalelementsofafiscalmeasurementstationhave been tested and demonstrated to be fully operational, with all necessary functionality and all relevant calculations being performed to within the required tolerances.

3.5.2 The OGA should be informed of the dates of all such testing activities. Exceptionally, representatives from the OGA may choose to attend. At least 2 weeks’ notice should be given to the OGA of the relevant dates.

3.5.3 The OGA may request to be provided with calibrationreportsforprimaryflowelements.

3.6 Final PON 6 Submission

3.6.1 ThefinalPON6submissionshouldinclude,asaminimum, the following supporting information:

• A statement of the method of measurement to be adopted (see 2.2. above).

• Aprocessflowdiagram,indicatingthelocationof the proposed metering and sampling points.

• Piping and instrumentation diagrams showingthedimensionsandconfigurationof the pipework immediately upstream and downstream of the metering and sampling systems.

• Proposed initial frequencies for the recalibration ofcriticalflowelements.

3.7 Formal Non-Objection from the OGA

3.7.1 Subject to the satisfactory completion of the PON 6 process (including any follow-up information requested by the OGA), the Operator will receive a letter of ‘non-objection’ to the proposed method of measurement from the OGA.

9 4. General Operating Principles | OGA Measurement Guidelines 2019

4.1 Risk-Based Maintenance Strategies

4.1.1 The OGA expects Operators of both pipelines and individual measurement stations to be open to the adoption of a risk-based approach to maintenance.

4.1.2 In such an approach, Operator experience is used to assess the likely overall effect, in terms offinancialexposure,ofincreaseduncertaintyin measurement at either the primary or the secondary element, and to balance this against the cost of its mitigation by re-calibration.

4.1.3 In considering the effect of increased measurement uncertainty, it is important use a statistical approach, rather than simply multiplyingtheuncertaintyfigurebythevalueflowrate,whichwillresultinanover-estimationoffinancialexposure.

4.1.4 A detailed risk-based approach is described in a number of papers5,6,7 from North Sea Flow Management Workshops8

4. General Operating Principles

5 Pashnina, N & Daniel, P. “Determination of Optimal Calibration Intervals – A Risk-Based Approach.” 34th International North Sea Flow Measurement Workshop, St. Andrews 2016.6Stockton,P.“Costbenefitanalysesinthedesignofallocationsystems.”27thInternationalNorthSeaFlowMeasurementWorkshop,Tønsberg2009.7Sætre,C.et.al“Anewmethodologyforcost-benefitriskanalysisofoilmeteringsystemlay-outs.”33rdInternationalNorthSeaFlowMeasurementWorkshop,Tønsberg20158 https://nfogm.no/documents/north-sea-flow-measurement-workshop/

10 5. OGA Inspection of Fiscal Oil & Gas Measurement & Allocation Systems | OGA Measurement Guidelines 2019

5.1.1 Under the terms of the licence, the OGA has a right to inspect any measurement station used to determine quantities of hydrocarbon won and saved from a licensed area on the UKCS. However, in keeping with the objective of MER UK, the OGA’s inspection programme is generally targeted at the areas of greatest financialrisktotheUK[Exchequer],including:

(i) Points of sale at onshore terminals in the UK

(ii) Measurement stations at entry points on shared transportation systems containing non-UKCS hydrocarbons (principally, oil and gas pipelines shared with hydrocarbons originating on the Norwegian continental shelf)

(iii) Measurement stations on trans-median or trans-boundaryfielddevelopments

5.1.2 For measurement stations that do not lie in the above categories, the OGA will generally rely on the measures put in place by pipeline Operators toensurethatthestandardsof‘goodoilfieldpractice’ are maintained.

5.1.3 The OGA may request access to reports produced on the key measurement stations by independent inspectors appointed by the pipeline Operator. (Several pipeline Operators already provide the OGA with this information on a routine basis.)

5.2 Inspection Planning

5.2.1 The OGA gives Operators as much notice as possible of its intent to carry out inspections, and will endeavour to co-operate with Operators’ offshore planning schedules. In return, the OGA expects Operators to treatinspectiondates,onceagreed,asfirmcommitments.

5.2.2 A typical inspection of an offshore installation is of 2-3 nights’ duration. Operators are expected to co-operate in arranging inspections within a window of Monday-Wednesday/Thursday or Tuesday-Thursday/Friday.

5.3 Inspection Format and Follow-Up

5.3.1 During the inspection, the OGA will seek to establish the extent to which the Operator of the measurement station is in compliance with the relevant pipeline requirements, and to assess the degree of control with which the measurement station is being managed.

5.3.2 An overall ‘score’ for the measurement station will be determined, based on two elements:

• Status during the inspection

• Perceived risk of mis-measurement

5.3.3 Following the inspection, the OGA will report itsfindingstotheOperator.Anopportunityforfeedback will be given to the Operator, and timeframesfortheresolutionoftheidentifiedissues shall be agreed.

5.4 UK/Norway Memorandum of Understanding

5.4.1 The UK has a long-standing Memorandum of Understanding (MoU)9 with the Government of Norway, setting out procedures for joint surveillance activities on measurement stations of common interest; an up-to-date list of these measurement stations is maintained in the associated Annex 1.

5.4.2 As per the terms of the MoU, from time to time, the measurement stations listed in Annex 1 will be inspected jointly by the OGA and representatives of the Norwegian Petroleum Directorate.

5. OGA Inspection of Fiscal Oil and Gas Measurement and Allocation Systems

5.1 First

9 https://www.ogauthority.co.uk/exploration-production/production/petroleum-measurement/

11 6. Dispensation and Deviation Management | OGA Measurement Guidelines 2019

6.1 Dispensations

6.1.1 Duringtheoperationallifeofafiscalmeasurementstation,significantdeparturesfrom the normal operating conditions may be expected to arise. The need to maintain measurement integrity must be balanced against the potential cost of remedial action.

6.1.2 In cases where the situation at a primary allocation point is expected to last more than a few days, a dispensation should be obtained from the relevant pipeline Operator. This should indicate the timeframe within which the matter is expected to be resolved.

6.1.3 Where there is evidence of poor dispensation management on the part of the Operator of a fieldorfields,theOGAmayinterveneinordertoestablish a course of remedial action.

6.2 Deviations

6.2.1 Where dispensations have been agreed, the aim is to ensure that appropriate remedial action takes place within agreed timeframes. There may be instances, particularly towards the end offieldlife,whereremedialactionisnolongereconomicallyjustified.Wheresuchasituationarises at a primary allocation point, a permanent dispensation should be agreed with the relevant Pipeline Operator.

6.2.2 Operators of primary allocation systems should be able to demonstrate that they have in place adequate systems of oversight so that such departures from normal operating practice may be detected and managed appropriately.

6. Dispensation and Deviation Management

12 7. OGA Pipeline Reviews | OGA Measurement Guidelines 2019

7. OGA Pipeline Reviews

7.1.1 From time to time, the OGA will meet with the Operators of shared transportation systems on the UKCS, in order to review:

• The performance of the individual measurement stations on the pipeline, with particular emphasis on those with relatively high throughputs

• The pipeline Operator’s management of measurement on the pipeline

7.2 Metering Station Performance

7.2.1 The review of the performance of metering stations at primary entry points will cover the following areas:

• Significantmis-measurementsraisedduringtheprevious twelve months

• Active and historic dispensations

• Independentinspectionfindings

• Meter performance and calibration history

• Sampling performance (for liquid hydrocarbons)

• Gas chromatograph performance (for gaseous hydrocarbons)

• Progress in closing out dispensations and independentinspectionfindingswithinagreedtimeframes.

• Maintenance strategy

7.2.2 Where there is evidence of poor practice, the OGA may pursue the matter with the Operator of the relevant measurement station.

7.3 Pipeline Management

7.3.1 As stated in paragraph 7.1.1, for shared transportation systems holding hydrocarbons originating solely on the UKCS, the OGA will generally rely on the pipeline Operators to ensure that‘goodoilfieldpractice’isfollowedattheprimary allocation points.

7.3.2 On at least an annual basis, the OGA will meet with pipeline Operators to review aspects of their

management of measurement including:-

• Pipeline balance

• Scheduling of independent inspections of measurement stations

• Dispensation and deviation management

7.3.3 The OGA may ask pipeline operators to assess entrants’ performance on the basis of a number of key performance indicators, indicating, for example:

• Progress in closing out points raised during independent inspections

• The percentage of dispensations closed out within initially-agreed timeframes

• Thenumberofsignificantmis-measurementsraised during the previous twelve months.

7.3.4 The use of ‘dashboards’, or equivalent, to summarise the performance of the measurement stations at primary entry points, is encouraged.

7.3.5 Where Operators of metering stations at primary entry points have concerns over aspects of pipeline regulation and these cannot be resolved by dialogue with the respective pipeline authority, the matter may be raised with the OGA. The OGA will consider the matter and may approach the pipeline authority to discuss the matter further.

7.1 7.1 heading

13 8. Offshore Loading Systems | OGA Measurement Guidelines 2019

8. Offshore Loading Systems

8.1.1 The majority of the liquid hydrocarbons produced on the UKCS is exported from production facilities via shared pipelines. However,asignificantproportionisexporteddirect to market via shuttle tankers.

8.1.2 The point at which the sale of oil takes place is a commercial decision on the part of the Operator. It may be either:

a) at the point of offshore loading, based on the Bill of Lading, or (more commonly)

b) at a ‘port of discharge’, based on the Outturn

Inthecaseofa),thefiscalmeasurementtakes place during the transfer of oil to the

shuttle tanker. This is generally achieved using measurement systems that are designed to custody transfer standards. The OGA may from time to time inspect such measurement stations to ensure that appropriate measurement standards are being maintained.

Inthecaseofb),thefiscalmeasurementislikely to be beyond the jurisdiction of the OGA. It is with this scenario that the remainder of this chapter of the Guidelines is concerned.

The OGA should be informed of the intended location of the point of sale at the PON 6 stage, since this essentially determines the measurement and reporting requirements.

Arm’s Length Sale

AsdefinedinPara.1ofSchedule3totheOilTaxationAct1975andtheprovisionsof section 282 of the Corporation Tax Act 2010, a sale is Arm’s Length if, and only if:

(a) the contract price is the sole consideration for the sale;

(b) the terms of the sale are not affected by any commercial relationship (other than that created by the contract itself) between the seller or any person connected with the seller and the buyer or any person connected with the buyer; and

(c) neither the seller nor any person connected with him has, directly or indirectly, any interest in the subsequent resale or disposal of the oil or any product derived therefrom.

Bill of Lading The quantity delivered from the offshore installation to the shuttle tanker. This is normally determined on the basis of measurements made on the offshore installation during the transfer to the shuttle tanker.

Ship’s Figures The quantity held on the ship, determined immediately following the transfer fromtheoffshoreinstallation,andagainimmediatelypriortooffloadattheportofdischarge.

Outturn The quantity measured at the port of discharge.

Vessel Experience FactorA correction factor applied to the Ship’s Figures, based on a statistical analysis of historic discrepancies from onshore (Outturn) values.

Definitions

8.1 8.1 heading

14 8. Offshore Loading Systems | OGA Measurement Guidelines 2019

8.2 OGA Measurement Expectations

8.2.1 Measurement of quantities of oil exported direct to market is required for the following reasons:

(i) As referred to in paragraph 1.2.1 , there is a licence requirement to determine quantities won and saved from the licensed area, using a method of measurement consistent with ‘goodoilfieldpractice’,andagreedatthePON 6 stage.

(ii) Thereisafiscalrequirementtodeterminequantities of oil sold, since this forms the basisofthecalculationofprofitfromoffshoreoperations, which is subject to Corporation Tax and the Supplementary Charge.

8.2.2 Having reviewed Bill of Lading versus Outturn data from over 500 cargoes delivered to ports of discharge from the UKCS during 2014-2019,theOGAiscurrentlysatisfiedthatthereis no evidence of any systematic bias in the determination of Outturn quantities. Moreover, provided there is good agreement between theOutturnfigureandtheShip’sFiguresimmediatelypriortooffload,cargoesaretypicallyaccepted without reference to the Bill of Lading.

8.2.3 Therefore, for cargoes sold on the basis of the Outturn, the OGA does not set any expectation on the uncertainty with which the Bill of Lading is to be determined.

8.2.4 The interests of all parties (including the Operator) at the port of discharge are normally represented by an Independent Cargo Inspector whose task it is to ensure that correct procedures are followed. A Marine Cargo Expeditor may also be appointed by the Operator to represent their interests at the port of discharge.

8.2.5 Where the sale of hydrocarbons is ‘Arms’ Length’, the interests of Operator and Government are aligned, since it is in the interests of both to ensure that the Outturn is maximised. Where the sale is not at Arm’s Length, the OGA may require further details of the independent scrutiny of the quantity of oil declared to have been sold.

8.3 OGA Reporting Requirements

8.3.1 The American Petroleum Institute (API)10 Manual of Petroleum Measurement, Chapter 17 (Marine Measurement) recommends that Operators, as part of their surveillance of the cargo transfer process, track critical parameters at four key points. These are:

• The total calculated volume delivered from the offshore installation (Bill of Lading).

• The Ship’s Figures, immediately post transfer from the offshore installation.

• TheShip’sFigures,immediatelypriortooffloadat the port of discharge.

• The total calculated volume measured at the port of discharge (Outturn).

8.3.2 The OGA requires that the following parameters are reported at each of the above points:

• Gross Standard Volume.

• Net Standard Volume.

• Sediment and Water.

• Standard density.

in order that the integrity of the overall cargo transfer process may be assessed.

8.3.3 For each cargo transferred, the following information should be provided:

• Anumericcargoidentifier.

• Thedateoftheoffloadtotheshuttletanker.

• The identity of the shuttle tanker.

• The location of the port of discharge.

8.3.4 In addition, the OGA requires the following informationforeachoffload:

• Was a ‘Vessel Experience Factor’, or equivalent, used in the determination of the Ship’s Figures?

• Did the sale take place at ‘Arm’s Length’?

• Is an independent cargo inspector’s report available?

• Is a marine expeditor’s report available?

10 www.api.org

15 8. Offshore Loading Systems | OGA Measurement Guidelines 2019

8.3.5 On a quarterly basis, Operators are expected to populate the standard OGA pro-forma11 with the above information and to send it to the OGA at the E-mail address [email protected].

8.3.6 The OGA uses this pro-forma to populate its owndatabaseofcargooffloadsfromtheUKCSto onshore ports of discharge. Operators may occasionally be requested to provide further details, for example where ship-to-ship transfers are involved, or where there is a consistent negative discrepancy between the offshore figures(BillofLadingand/orShip’sFigures)andthe Outturn.

11 https://www.ogauthority.co.uk/exploration-production/production/petroleum-measurement/

16 9. Production Separator Measurement for Allocation Purposes | OGA Measurement Guidelines 2019

9. Production Separator Measurement for Allocation Purposes

9.1 Introduction

9.1.1 The OGA will consider the use of dedicated separatormeasurementforfiscalpurposeswherethisisdictatedbyfieldeconomics.Thisisoftenthecasewhennewsatellitefieldsaretied back to older ‘host’ facilities. New modules may be provided with dedicated separators for thesatellitefield.However,amorecommonscenario is where a pre-existing process separatorisdedicatedtothenewfield.Theremay be serious measurement challenges where measurementsystemsareretro-fittedontoseparatorsthatwerenotdesignedwithfiscalmetering in mind.

9.1.2 This chapter of the Guidelines is intended to provide Operators with an indication of the OGA’sexpectationswherefiscalmeasurementsystems are installed on the outlets from process separators.

9.1.3 Theuseoftestseparatorsinfiscalapplicationsis considered elsewhere in Chapter 10.

9.2 Separator Design

9.2.1 While the measurement on the outlets of the separators may be nominally ‘single-phase’, it must always be borne in mind that this may not be the case in practice. Any departure from single-phaseconditionsmayleadtoasignificantincrease in measurement uncertainty.

9.2.2 Where the use of a new separator is proposed, it should be designed to ensure that the measurement at each outlet is single phase.

9.2.3 Whereitisproposedtoretro-fitafiscalmeasurement system onto an existing separator, the Operator should take all reasonable steps toensurethatasingle-phaseflowregimeisinplace at each outlet.

9.3 Separator Capability

9.3.1 With the above requirements in mind, a review of separator capability should take place.

9.3.2 Provision should be made for adequate secondary instrumentation (e.g. temperature, pressure measurement) at locations where the parameters measured are representative of those at the meter.

9.3.3 The OGA may require the Operator to perform reviews of certain critical design aspects of the proposed measurement system (for example, the use of on-line versus off-line measurement and analysis techniques) in order to determine theoptimalsolutionfromthecost/benefitstandpoint.

9.4 Maintenance Frequencies

9.4.1 Initial recalibration intervals should be proposed at the PON6 stage, using a risk-based approach.

9.4.2 The potential use of diagnostic facilities should be strongly considered at the design phase.

9.4.3 Separator outlets must be provided with adequateisolationvalvessothattheflowelements may be removed for inspection and/or recalibration without requiring a process shut-down.

9.5 Sampling

9.5.1 Operating conditions (pressure, temperature) at the separator are likely to differ – possibly substantially - from those at the export metering station. A commonly-adopted allocation methodology is to ‘pro-rate’ the outputs from one or more separators so that their sum agrees with the total exported from the installation. In such cases, knowledge of the compositions of the oil and gas at each separator is critical in order that the phase changes between

17 9. Production Separator Measurement for Allocation Purposes | OGA Measurement Guidelines 2019

separator and export metering may be modelled effectively; sampling is therefore an important part of the overall measurement and allocation strategy.

9.5.2 Sampling may also be required in order that the water-in-oil content may be determined.

9.5.3 Where samples are to be collected for analysis, the frequency of sampling shall be agreed with the OGA at the PON 6 stage, and may be reviewed from time to time thereafter.

9.6 Measurement Technologies

9.6.1 The choice of metering technology to be employed on each leg is critically important, since some technologies are more suited than others to typical separator applications.

9.6.2 Particular attention must be paid to the following factors at the proposed location of each meter:

• Thelikelyflowprofile.

• Thelikelihoodoftwoorthree-phaseflowoccurring

9.6.3 The choice of meter technology for each outlet will be discussed and agreed with the OGA at the PON 6 stage.

(i) Liquid Outlet Measurement

The most commonly occurring issue that must be dealt with on the liquid outlet of separators is that of gas breakout. Certain otherwise-desirable technologies (such as Coriolis meters) introduce relatively high degrees of headloss,whichmaybesufficienttocausethe liquid to change phase at the meter.

Operators should take all reasonable steps to reduce the probability of such gas breakout. Measurement should take place as far as practically possible beneath the level of the separator itself, in order to maximise the staticheadattheflowmeter.Cyclicpressurefluctuationsinthepressureseparatormaycause corresponding cyclic gas breakout at the meter. The use of a pump to increase the pressure at the meter should also be considered.

Unless direct mass measurement (via Coriolis meter)issufficientforallocationpurposes,provision should be made for the determination of liquid density. This may be based on direct measurement or on the off-line analysis of representative samples. In two-phase applications where the water content is determined via an off-line calculation based on wet-oil- and base-densities, the reference density must be kept up-to-date since this technique is highly sensitive to changes in base density.

Provision should be made for manual sampling attheliquidoutlet.Theuseofanon-lineflow-proportional sampler may also be required in systems with relatively high throughputs, or where the separator is to be operated in 2-phase mode. The approach to be taken shall be agreed with the OGA at the PON6 stage.

The water content may be determined by either by the use of an on-line water-in-oil meter, or by off-line analysis of representative samples.

(ii) Gas Outlet Measurement

When selecting the relevant measurement technology for the gas outlet, Operators must consider the possibility of liquid carry-over and its resultant effect on measurement uncertainty.

Provision should be made for manual sampling at the gas outlet. The use of on-line densitometers may well be precluded by the possible presence of liquids. Gas composition is commonly determined by the off-line analysis of representative samples. However, the use of gas chromatographs may be appropriate in some cases, as the additional installation and operation costs may be more than offset by the reduction in overall measurement uncertainty.

(iii) Water Outlet Measurement

Where the water measurement forms part of the allocation system, the choice of meter should be discussed with the OGA.

18 10. Test Separator Measurement for Allocation Purposes | OGA Measurement Guidelines 2019

10.1 Introduction

10.1.1 The use of test separator measurement systems forfieldallocationpurposesispossibleundereither of the following scenarios:

• Where the agreed Method of Measurement for therelevantfield(s)is‘FlowSampling’,i.e.wherefluidsareallocatedtooneormorelicensedareas on the basis of periodic single-phase measurements on the test separator.

• Where the agreed Method of Measurement fortherelevantfield(s)isbasedonmultiphasemetering, with the multiphase meter (MPFM) periodicallyverifiedagainstthetestseparator.

10.1.2 Note: Wet Gas metering may be considered as a subset of Multiphase Metering for this purpose.

10.1.3 Flow meter performance during well testing may fall far short of the levels potentially achievable in single-phase laboratory applications. Nevertheless, these uncertainties may be minimised by the adoption of best practice.

10.2 Test Separator Design

10.2.1 In either of the two scenarios described above in paragraph 10.1.1, the test separator is unlikely tohavebeendesignedwithfiscalservicein mind. In order to minimise measurement uncertaintytoanacceptablelevel,asignificantupgrade of the test separator metering and/or instrumentation may be necessary.

10.2.2 The relevant considerations in such circumstances are similar to those already described for dedicated process separators. However, it must be borne in mind that the measurement challenges are likely to be more pronounced in Test Separator applications.

10.2.3 The choice of meter for the gas and liquid phases should be considered carefully.

10.2.4 Sampling facilities should be provided to enable representative samples to be obtained.

10.3 ‘Flow Sampling’ – Well Test Procedures

10.3.1 Where ‘Flow Sampling’ is the agreed method of measurement, an agreed frequency of well tests should be agreed with the OGA, and stated in the PON6.

10.3.2 The OGA will normally require the Operator to carry out a review of the relevant well-test procedures. These should include details of:

• The planned duration of the well tests (this should take into account the peculiarities of individual wells, e.g. long-distance tie-backs may requirelongerfortheflowtostabilise).

• The method by which well test details (e.g. well-headflowingpressure,chokeposition)shallberecorded.

• Themethodbywhichfluidcompositionshallbedetermined during the well test.

10.3.3 The relevant procedures should be made available for review by the OGA.

10.4 Multiphase Measurement – MPFM/Test Separator Comparison Procedures.

10.4.1 Where the agreed Method of Measurement is ‘Multiphase Metering’ with the multiphase meter (MPFM)periodicallyverifiedagainstthetestseparator, an agreed frequency for the relevant comparisonswill be agreed with the OGA and stated in the PON 6.

10.4.2 The Operator should prepare written procedures for the periodic comparisons. These should include details of:

• Theflowstabilitycriteriarequiredforthetesttotake place.

• The planned duration of the comparisons.

• The basis on which the comparison shall be made (e.g. mass, volume at standard conditions – per phase, and total).

• Themethodbywhichfluidcompositionshallbedetermined during the comparison.

10. Test Separator Measurement for Allocation Purposes

19 10. Test Separator Measurement for Allocation Purposes | OGA Measurement Guidelines 2019

• The acceptance criteria for considering any test to have been successful, with a documented investigation plan for when these criteria have not been met.

10.4.3 The relevant procedures should be made available for review by the OGA.

20 11. Multiphase Measurement in Allocation Applications | OGA Measurement Guidelines 2019

11.1.1 Theuseofmultiphaseflowmeters(MPFMs)inallocation applications is now well established on the UKCS. The OGA and its predecessors have long accepted that their use in such applications is essential if the remaining reserves in the North Sea are to be exploited.

11.1.2 The increased use of MPFMs is attributable to this fact, and also to the undoubted improvements in meter performance that have been achieved over the past two decades.

11.1.3 The uncertainties that can be achieved by MPFMs are typically application-dependent andmaynotalwaysbequantifiable.However,measurement uncertainty can be minimised by the adoption of best practice in meter selection, maintenance,operationandverification.Thissection of the Guidelines outlines the OGA’s expectations on Operators with this overall aim in mind.

11.2 Typical Applications of MPFMs

11.2.1 Multiphase measurement may be appropriate in production allocation applications where hydrocarbonsfrommorethanonefieldarecommingled in a shared production facility, and wherecost-benefitconsiderationsindicatethatsingle-phasemeasurementofeachfieldcannotbeeconomicallyjustified.

11.2.2 There are a number of challenges surrounding the use of MPFMs, most notably associated withsamplingandmeterverification.

11.2.3 The table below indicates some of the typical configurationsinwhichMPFMshavebeenusedinfiscalapplicationsintheUKsectoroftheNorth Sea.

11. Multiphase Measurement in Allocation Applications

Application MPFM Verification Method Comments

MPFM topsides on ‘host’ facility, measuring all wells from a single ‘satellite’ field.

Comparison of MPFM with test separator.

Relatively straightforward in view of proximity of MPFM to test separator.

Allocationtosatellitefieldrelativelystraightforward.

PVT data required periodically; frequency higher where individual well characteristics believed to be significantlydifferent.

MPFM subsea, measuring all wells from a single satellite field.

Comparison of MPFM with test separator. Relatively complex comparisoninviewofsignificantlydifferent process conditions at MPFM/Test Separator, and in view of distance between these. Procedures must take account of possibility of slugginginflowline,etc.

Allocationtosatellitefieldrelativelystraightforward.

PVT data required periodically; frequency higher where individual well characteristics believed to besignificantlydifferent.However,inpracticeitmaybedifficultorimpossibletoupdateinitialPVTdata.

MPFM subsea, measuring all wells from more than one satellitefield.

Comparison of MPFM with test separator.

Relatively complex comparison in viewofsignificantlydifferentprocessconditions at MPFM/Test Separator, and in view of distance between these. Procedures must take account of possibility of slugging in flowline,etc.

Highly complex allocation issues.

At least one MPFM manufacturer offers the possibility of a ‘switching’ facility whereby individualwellsorgroupsofwellsmaybeflowedseparately through the MPFM.

PVT data required periodically; frequency likely tobehigherthanintheabovecase,sincefluidcharacteristics likely to show greater variability. However,inpracticeitmayagainbedifficultorimpossible to update initial PVT data

11.1 11.1 heading

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11.3 Meter Selection

11.3.1 The process of meter selection is one where close co-operation between vendor and Operator is required.

11.3.2 To facilitate meter selection, the Operator must establishtheproductionprofileandtherangeof pressures, temperatures and compositions that will be measured by the MPFM during its period in service. This should permit the vendor todeterminethesizeandspecificconfigurationof the meter.

11.3.3 TheeventualdeclineinflowratemaybesufficienttorequirethereplacementoftheMPFMwithasmallermodel.Duringthefieldlife,fluidcompositionmaychangesufficientlyto necessitate a change in the meter type. (For example, gas volume fraction (GVF) will increasesignificantlyasthereservoirpressuredrops below bubble point and it may become necessary to change from a MPFM to a wet gasflowmeter.)

11.3.4 Vendors’ performance data should be compared in a ‘like-for-like’ manner in order that the optimal MPFM for a particular applicationmaybeidentified.

11.3.5 It is recognised that the different multiphase measurement technologies are each better suited to some applications than to others. For example, where high-water-content wells are to be measured, the use of capacitance-based techniques to infer water content may be inadvisable since the technology may requireoil-continuousflowforittooperatesuccessfully. Equally, if the produced oil is heavy then its properties in terms of ionising radiation can approach those of water; in such cases discrimination between the oil and water using dual-energy radiation techniques may prove challenging.

11.3.6 All MPFMs depend on knowledge of the propertiesofthemeasuredfluids.Whenthefluidpropertieschange,systematicbiasinthe output of the MPFM may be expected unless the relevant parameters in the meter

softwareareupdatedtoreflectthesechanges.Unfortunately, it may not always be possible to detect such changes in practice – particularly in remote applications such as subsea MPFMs. However, some types of MPFM may be more insensitive than others to the sort of changes influidpropertiesthatarepredictedforagivenapplication.

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11.4 Service and Maintenance Agreements

11.4.1 To a greater extent than for any other type ofprimaryflowelementusedinoilandgasmeasurement, the successful operation of MPFMs requires the continued active participation of the meter manufacturer throughoutthelifeofthefield.Therefore,service and maintenance agreements should be set up at the outset. The possibility of remote monitoring by service engineers should be utilised wherever possible.

11.5 Onshore MPFM Calibration

11.5.1 Operators are strongly urged to exercise caution in interpreting claimed MPFM uncertainties.Thesefiguresarelikelytobebased on empirical test data. Where such test data is used to support the decision to use a particular meter, Operators must establish that the data is not ‘selective’ (i.e. ‘best case’).

11.6 Onshore Calibration - Static Testing

11.6.1 The static tests performed on a MPFM vary from one model to another. However, the general purpose of such tests is to establish areferencebasedonaknownfluidinsidethemeasurement section of the MPFM.

11.6.2 This may consist of measurement of:

• Geometric dimensions,

• Calibration of differential pressure cell,

• Verificationofγ-ray count rates in calibration fluids(oil,gas,water),dependingontheworking principle of the primary measurement elements.

11.6.3 Such calibrations are normally carried out irrespective of the conditions in which the meter will ultimately be used.

11.7 Onshore Calibration – Flow Loop Tests

11.7.1 Operators are strongly urged to arrange for dynamic(flowloop)teststobecarriedoutprior to agreeing to the use of a MPFM in an allocation application. It may be appropriate to test the meter ‘blind’, i.e. where the vendor has

nopriorknowledgeofthefluidconditionsintheflowloop.

11.7.2 Theaimofsuchtestsistocomparetheflowrates (oil, gas, water) indicated by the MPFM with the values measured by the reference standardflowratesforeachphaseoverthefull range of anticipated operating conditions. Where it is not possible to test the MPFM over the full operating envelope, it may nevertheless be worthwhile to perform a dynamic calibration of the meter; this may serve as a ‘dynamic functionality check’. Where the comparison is on a volume basis, it should be referred to a common set of conditions (e.g. standard conditions) and must take account of possible transfer between phases.

11.7.3 Thecalibrationfluidsmaybeeither‘process’(live crude, hydrocarbon gas, formation water) or ‘model’ (e.g. oil, water, nitrogen). The latter set-up is by far the most common; not only is it far less hazardous to operate but thePVTcharacteristicsofthefluidsarelikelyto be relatively well understood, so that it becomes possible to compare the reference measurements with those of the MPFM with minimal additional uncertainty.

11.8 System Integration Test

11.8.1 Before the MPFM and its associated secondary instrumentation is installed offshore, testing should take place to ensure the correct operation of the system as a whole (communication between devices, data hand-over, etc.). This is particularly important in subsea applications.

11.9 Offshore Calibration – Static Testing

11.9.1 The aim of in situ static testing is to verify that the MPFM characteristics have not shown any significantchangecomparedtothestatictestresults obtained onshore.

11.9.2 Some models of meter require an initial static calibrationusingactualwellfluids.Similartestsmay be repeated at regular intervals during the meter’s time in service. A comparison of these results over time serves as a useful health check.

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11.10 Comparison of MPFM with Test Separator

11.10.1 When the MPFM is used to measure a well stream that is occasionally routed through the test separator, the test separator may be used to verify the performance of the MPFM.

11.10.2 WhenevertheOperator’sreverificationstrategydepends on periodic comparison of the MPFM with the test separator, the OGA will seek assurances that all reasonable steps have been taken to minimise the uncertainty of measurement of the separator’s gas, oil and water phases.

11.10.3 During the comparison, the MPFM and test separatormaybeatsignificantlydifferentconditions of pressure and temperature. Correcting the respective gas and oil volumes measured during the comparison to standard conditions requires knowledge of the hydrocarbons’ composition, and involves additional uncertainty inherent in the process model. The possibility of mass transfer between phases must also be taken into account. Comparisons of the MPFM and test separator data should include the total mass measured in all three phases.

11.11 VerificationTechniques

11.11.1 Some MPFM models now feature diagnostic facilities which provide qualitative indications of meter performance.

11.11.2 With the agreement of all parties, these have the potential to allow the interval between successivemeterverificationstobeextended.

11.12 Sampling

11.12.1 Compositional analysis is invariably required in fiscalapplications.Inthecaseofproductionallocation using MPFMs, this is for the following reasons:

• All MPFMs depend, to a greater or lesser extent,onknowledgeoffluidcharacteristicsfortheir correct operation.

• PVT data may be required to model the phase behaviour of the oil and gas measured by the MPFM. This may be to test separator conditionsforverificationpurposes(whenthecomparison is in volume units – see below), or to export conditions for allocation purposes.

• Obtaining a compositionally-representative samplefromamultiphasefluidatisothermaland isobaric conditions is likely to be one of the mostchallengingaspectsoffiscalmultiphasemeasurement. This is particularly true of subsea MPFM applications.

11.12.2 PVT information should be updated periodically. Operators should have in place a programme whereby certain key events (for example, the start of water-injection) ‘trigger’ a new programme of sampling.

24 12. Wet Gas Measurement in Allocation Applications | OGA Measurement Guidelines 2019

12.1.1 The uncertainties that can be achieved by wet gas meters are typically application-dependent andmaynotalwaysbequantifiable.However,measurement uncertainty can be minimised by the adoption of best practice in meter selection, maintenance, operation and verification.ThischapteroftheGuidelinesoutlines the OGA’s expectations on Operators with this overall aim in mind.

12.1.2 Wheremultiphaseflowmetersareusedin‘wet gas’ mode, the same considerations apply regarding meter selection, testing and calibration – Operators should consult Chapter 11 of these Guidelines for an indication of the OGA’s expectations.

12.1.3 This chapter is intended to provide Operators with guidance on the use of generic (non-manufacturer-specific)differentialpressuremetersinfiscalwetgasapplications.

12.1.4 The publication of the results of research work at North Sea Flow Measurement Workshops and elsewhere is an invaluable source of information, particularly in the area of wet gas measurement where the information is likely to be available via this route many years before it appears in a standard.

12.2 Differential Pressure Meters

12.2.1 Whenwetgasflowpassesthroughadifferentialpressure(ΔP)meter,thepresenceof liquid results in an increase in the measured ΔP.Asaresult,themeterover-estimatesthegasflowrate.Thedegreeofover-estimationdepends on a number of factors – the Lockhart Martinelli parameter, the gas to liquid density ratio (essentially the operating pressure), the gas densiometric Froude number and the water-liquid ratio.

12.2.2 Venturi meters are most commonly used in wet gas applications. A number of correlations have been developed in order to correct the over-reading of Venturi meters in the presence

of liquid, over a limited range of meter parameters (e.g. meter size and β-ratio) and operating conditions.

12.2.3 Recent work by industry has highlighted the factthatdespitethelackofattentiononorificeplateresponsetowetgasflows,thereisinfact much to recommend their use. Provided theorificeplatedoesnotsustaindamage,its response is repeatable, reproducible and therefore predictable. Flow visualisation studies have shown that the risk of liquid beingtrappedbehindtheorificeplatehasbeen over-stated. Furthermore, a correlation has been developed for 2” to 4” meters that is essentially independent of β-ratio.

12.2.4 In general, differential pressure meters in wet gas applications behave more like their single-phase equivalents as pressure is increased.

12.2.5 The use of meter, and the correlation to be used, should be discussed with the OGA at the PON 6 stage.

12.3 Determination of Gas and Liquid Density

12.3.1 The liquid and gas densities may be determined by laboratory analysis of representative samples. Sampling of wet gas flowsisnottrivialandcarefulconsiderationmust be given to the design and operation of the sampling system. The use of fully-automatedflow-proportionalsamplingsystems is generally precluded by the marginal natureofwetgasfielddevelopments,sothat intermittent manual sampling is the most commonly-employed tactic. In such cases, the question of sampling frequency must be carefully considered.

12.3.2 Therearespecificpracticalissuesarisingfromthe nature of many of the nominally ‘dry’ gas fieldsinthesouthernsectoroftheUKNorthSea. Many of these have been shown to begin toproducesignificantquantitiesofliquidas

12. Wet Gas Measurement in Allocation Applications12.1 12.1 heading

25 12. Wet Gas Measurement in Allocation Applications | OGA Measurement Guidelines 2019

they mature. In such cases, identifying the point at which liquid production begins is key.Incaseswherefieldsaredevelopedvia‘normally unattended’ installations (NUIs), it may be necessary to schedule visits for the specificpurposeofobtainingrepresentativesamples. Where this is not practicable, process simulation may be an acceptable alternative.

12.4 Determination of Liquid Content

12.4.1 A number of techniques have been developed forthedeterminationoftheflowrateoftheliquidcomponentofawetgasflow.Forexample, it may be possible to determine the liquid content from the analysis of representative samples (as described above). An estimate of liquid content can potentially be obtainedwhenitispossibletoroutetheflowthrough a test separator.

12.4.2 In wet gas applications the pressure loss across a Venturi is generally much greater than in analogous dry gas situations. Methods have been developed to determine the liquid loading as a function of the pressure loss across the Venturi. This has the potential to eliminate the need for a separate technique to determine water content.

12.4.3 The proposed method to determine liquid content should be discussed with the OGA at the PON 6 stage.

12.5 Comparison of Wet Gas Meter with Test Separator

12.5.1 It is recognised that in many wet gas applications it may not be possible to place the wet gas meter in series with the platform test separator. However, when this is achievable it provides an opportunity to verify the performance of the wet gas meter.

12.5.2 In such cases the procedures to be followed are the same as those described in the analogous section in the chapter on Multiphaseflowmetering.

26 13. Well Flow Rate Determination for Reservoir Management | OGA Measurement Guidelines 2019

13.1.1 As part of the OGA’s wider Stewardship process(SeeReference[1]atend),theOGA’s Metering Team may periodically review Operators’ strategies and procedures for well testing.

13.1.2 Theflowrateofeachofthethreephases(oil,gas and water) produced by a well is typically determined by periodic ‘well testing’, whereby flowfromthewellisdivertedeitherto:

(i) a test separator, equipped with single-phase meters on each of the outlets, or (more rarely)

(ii) amulti-phaseflowmeter(MPFM).

Thesesingle-phaseflowratesaretypicallyused as input to reservoir models.

Unfortunately, the well testing process is subject to a relatively high level of uncertainties and systematic measurement errors may be expected to occur.

13.2 Factors Affecting Well-Test Results

(i) Single-phase measurements

13.2.1 The nominally single-phase measurements of oil, gas and water on the outlets of a test separator are likely to be subject to installation effects, leading to measurement bias.

13.2.2 The calibrations conditions of the single-phase meters (assuming they have been calibrated at all) are unlikely to be representative of those experienced by the meters in service. Space and residence-time constraints may result innon-idealflowprofilesatthemeters.Flowthrough the meters may be only nominally single-phase; gas breakout at the oil meter and the presence of liquids in the gas meter are likely in many typical test separator applications.

13.2.3 In practice, Operators have typically been more concerned with the repeatability of the meters used in well-test systems – and in the

ability to detect trends – rather than in the uncertainty of the single-phase measurements.

13.2.4 Recent work has suggested that even well-maintained and well-operated separators will have uncertainties in the range of 2-4% on liquid (water and oil, separately), and 2-5% on gas. Where conditions are less than ideal, errors above 5% on liquid, and 10-15% on gas,areoftenencountered.[2]

(ii) ‘Reconciliation’ of well test results

13.2.5 In most cases, single-phase measurements of the commingled production from all of thewellsinthefieldtakesplaceataloweruncertainty downstream of the test separator. Production from each individual well is ‘pro-rated’, so that the sum of production of each phase from each well matches that produced from the reservoir as a whole. In practice, reconciliation factors tend to be systematically below1(andintherange0.85-0.90).[2]

13.2.6 In pro-rating volume production rates from each phase for each well, transfer between the phases must be considered. Thus, if the operating pressure is lower at the point where the commingled production is measured than it was at the test separator, transfer from the liquid to the gaseous phase may take place. This process may be modelled, but the modelling process (which is itself inherently uncertain) depends on knowledge of the physical properties of the hydrocarbons produced by the well; this is determined by laboratory analysis of samples obtained during the well test.

13.2.7 The effect of the reconciliation exercise is that well test results are given an inherent bias. The scale of the bias depends on the magnitude of the reconciliation factor; the absolute effect on an individual well is proportional to the share of that well’s production to that of the reservoir as a whole.

13. Well Flow Rate Determination for Reservoir Management13.1 13.1 heading

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(iii) Well test frequency

13.2.8 In general, there is no regulatory requirement from the OGA to test individual wells at any given frequency. The only exception to this is when well-testing forms the basis of the methodofmeasurementforthefieldasawhole, as agreed at the PON 6 stage; then the OGA typically expects wells to be tested at monthly intervals.

13.2.9 Forreservoirmodellingpurposes,flowrates between well tests are estimated by interpolation, using an assumed decline curve. In general, the greater the time between successive well tests, the higher the uncertainty inherent in this process.

13.2.10 In general, higher-producing wells should be tested at greater frequencies.

(iv) Well test duration

13.2.11 Itmaybedifficulttoobtainrepresentativeconditions during well tests. This is particularly true in the case of wells tied back to a platform overlongdistances,whenunstableflowand/or slugging may be anticipated.

13.2.12 The demands of well testing – for example, the time taken to obtain stable conditions – must always be balanced against wider operational requirements, and often, the duration of well tests will be curtailed as a result.

13.2.13 As a consequence, well tests may take place duringperiodsofunstableflow(withresultantmeasurement error), or the results may be unrepresentative.

(v) Test separator availability

13.2.14 Where a test separator is not available (for example, when the separator has been dedicated to use as a production separator forasatellitefield),orwhereproductionfroman individual well or group of wells cannot be diverted to the test separator, it may be possible to adopt the strategy of ‘well testing by difference’. However, while it is possible to minimisetheassociateduncertainties[3],suchan approach inevitably results in less reliable data than direct well testing.

It also relies on deferment of production from the well under ‘test’.

13.3 Effect of Bias and/or Uncertainty in Well-Test Results

13.3.1 Data used in reservoir simulation models are adjusted so that the output from the simulationmatchesobservedflowrates,inaprocess known as ‘history matching’. Where theseobservedflowratesareinerror,thehistory matching process - and by extension the reservoir simulation as a whole - is compromised.

13.3.2 Recent modelling work performed for the OGA has determined the effect of bias in well test results on the determination of Recovery Factor (RF) for a typical North Sea reservoir. For the reservoir modelled, the error in RF for a-10%biasinoilflowratewas~-15%;fora+10%biastheerrorinRFwas~+4%.Thus,negative errors have a proportionately larger effect.

13.3.3 The use of incorrect Recovery Factor has many consequences, some of them serious:

• The ultimate recovery from a reservoir may be adversely impacted.

• Business decisions (such as the location ofinfillwells)thatarebasedonreservoirmodelling may be based on information that is insufficientlyrobust.

• ThecalculationofProductionEfficiency–akeymetric for Industry and the OGA alike - may be compromised, as a result of the incorrect determination of well potentials.

• Anticipatedproductionfiguresarelikelytobein error; this will impact on business planning decisions (not to mention applications for Production and Flare Consents from the OGA).

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13.4 OGA Review of Well Testing

13.4.1 The OGA may from time to time review Operators’ well-test strategies and procedures for individual assets.

13.4.2 Considering each of the ‘factors affecting well tests’, as listed above, in turn:

(i) The degree of reliability of the single-phase measurements can be determined relatively easily by considering factors such as calibration and maintenance histories, Piping and Instrumentation Diagrams of the test separator and associated pipework.

(ii) The magnitude of the reconciliation factor for each phase (as well as that for total mass) provides perhaps the single most valuable metric for assessing the reliability of the well test regime as a whole. The further the factor is from 1, the greater the overall uncertaintyandpotentialforsignificanthidden bias.

(iii) Historic well test frequencies may be reviewed.

(iv) The planned and actual duration of well tests, and the associated procedures (including sampling) may be reviewed. Taken together with (iii) above, this may be used to inform the OGA’s opinion regarding the degree of robustness of the well-test strategy as a whole.

(v) Well testing ‘by difference’ determines a nominalflowratefromeachwell.Whenallwellsareflowingtogether,thesumofthesenominalflowrateswilldifferfromthemeasured,combined,flow.

(vi) Thedegreetowhichthesetwofiguresdifferprovides an indication of the robustness of the ‘by difference’ method.

13.4.3 The OGA may exceptionally require Operatorsofhigher-producingfieldstocarry out uncertainty calculations on their well-testsystems.Thequantitativefiguresresulting from such studies would provide qualitative indicators on the reliability of metrics such as recovery factor, production efficiencycalculationsorproductionconsentcalculations, based on the degree of confidenceinthewell-test-andbyextension,reservoir modelling – regimes as a whole.

13.4.4 Whereintermittentwellflowratedeterminationis clearly unsatisfactory, the OGA may recommend the use of non-intrusive (‘clamp-on’)technologiestoprovidecontinuousflowrate measurement.

13.5 References/Notes

[1] OGA Stewardship Expectation No. 6 (SE06) – Integrated Field Management12

[2] Pinguet, B. “A way forward to comparison of MPFM tests from flow-loop to field conditions.” SE Asia Flow Measurement Conference, 2017

[3] Zimmerman, M.; Haldipur, P.; Sheridan, M. “Managing By-Difference Well Testing Challenges in a Dynamic Subsea Flow Production Environment.” Upstream Production Management 2015.

12 https://www.ogauthority.co.uk/media/5900/oga_se6_integrated_fields_july_2019.pdf

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